In recent posts, we have discussed how Order 841 issued by the Federal Energy Regulatory Commission (“FERC”) on February 15, 2018 is expected to create new opportunities for the expansion of grid-scale (“in front of the meter”) energy storage. Order 841 is intended to encourage deployment of energy storage by addressing participation of energy storage resources in wholesale electricity markets operated by Regional Transmission Organizations (“RTOs”) and Independent System Operators (“ISOs”).

Since FERC issued Order 841, it has become apparent that RTOs and ISOs will face challenges in revising their tariffs to develop participation models that better incorporate energy storage into the market. Stakeholders need to participate in this process, as there are many issues left open to future resolution. We have highlighted below some of these issues and their potential importance to stakeholders.

State v. Federal Jurisdiction. RTOs and ISOs are uncertain about the overlap of federal and state authority posed by Order 841, particularly at the distribution level (as opposed to the wholesale level.) A FERC petition filed by PJM Interconnection LLC on April 9, 2018 to address state clean energy subsidies brought to the forefront the emerging conflict between state energy policies and federal regulation of wholesale electricity markets. State and federal interests do not always align -- states have the authority to give preference to certain types of energy resources (e.g., renewables), while FERC has the obligation to ensure that electricity generated by these resources is sold at just and reasonable rates.

Resilience. FERC (and many states) are seeking to expand the role of energy storage in furthering the goal of grid resiliency. This issue has taken on increased importance given the lack of enthusiasm for proposals to compensate coal and nuclear facilities that maintain on-site fuel reserves.

Transmission and Generation Infrastructure. Advocates of energy storage contend that it is a solution to both transmission and generation needs. Questions remain, however, regarding the adequacy of current transmission incentives policies, and whether they are sufficiently inclusive.

Financial Viability of Energy Storage Projects. Notwithstanding the issuance of Order 841, many investors and lenders are not persuaded yet that energy storage projects will (1) provide sufficiently long-term, concrete and reliable revenue streams; (2) offer technologies that are well-proven and reliable; and (3) achieve adequate participation by creditworthy counterparties or those that have access to financial assurance instruments such as performance insurance.

Complexity of Participation Models. Because energy storage projects may generate economic benefits through one or more different value streams, the preparation of participation models by RTOs and ISOs will be challenging. Stakeholders will need to find a cost-efficient way to get a “seat at the table” with policy makers and regulators managing this process.

Federal Tax Policy. Currently, the federal investment tax credit is only available to energy storage projects that are an inherent part of a larger renewable energy project. This is believed to have created an artificial distinction between stand-alone energy storage projects and “paired” projects, and a disincentive to invest in the former.

Need for Policies that are “Technology Agnostic.” Although FERC Order 841 is “technology agnostic” on its face, subsequent debate on implementation has focused almost exclusively on batteries. States must be encouraged to offer a “level playing field” to historical approaches such as “pumped storage,” as well as the newer generation of energy storage technologies including advanced battery storage.

Permitting. Policy makers and regulators need to establish flexible requirements that allow energy storage projects to be permitted as either generation or transmission projects. Environmental permitting requirements should be reasonable so as not to deter innovation.

Implementation details of the participation models will be driven at the RTO/ISO level. Compliance filings by RTOs and ISOs originally were due on December 3, 2018, but on April 13, 2018, FERC issued a “Tolling Order” to allow it more time to consider various motions for clarification and requests for rehearing filed in response to Order 841. Nonetheless, system operators are moving forward to comply with the requirements of Order 841. The policies adopted by RTOs, ISOs and states in establishing participation models likely will have a significant impact on the advancement of renewable and energy storage resources. Thus, stakeholder involvement is critical.

On July 18, 2018, the U.S. Congress House Committee on Energy and Commerce held a hearing to assess the progress being made by federal and state governments to promote the role of energy storage in the U.S. electrical system. A panel of five witnesses – an executive from the California Independent System Operator (“CAISO”); a partner at an energy and environmental economic consulting firm; and executives from E.ON, Fluence Energy, and Duke Energy – were present to testify and answer questions of the legislators.

The experts were largely favorable in their assessment of the steps taken by the federal government to promote energy storage and reduce existing barriers through opening up wholesale markets. In particular, there was a nearly universal consensus that FERC Order 841 (February 2018) had the desired effect of catalyzing energy storage’s role in the electrical grid by directing Regional Transmission Operators (RTOs) and Independent System Operators (ISOs) to create market rules for energy storage participation in the wholesale energy, capacity, and ancillary services markets. However, the testifying experts also expressed the view that Order 841 was but an initial step to promote energy storage, and that additional measures must be taken to allow energy storage to reach its full potential by clarifying certain provisions of the order, creating of additional policies and roadmap(s), and creating federal tax credits. Moreover, most experts agreed that finalizing Order 841 and 845 (Order revising the definition of generating facility to explicitly include energy storage) and denying requests for a rehearing would speed up the implementation process.

A prominent talking point focused on the need to extend federal tax credits to energy storage projects, particularly those that were not incorporated into larger renewable energy developments and are eligible to receive an investment tax credit (“ITC”). Most notably, the experts concurred that extension of the ITC to include stand alone energy storage projects would both lower the cost of the investment and accelerate its implementation. A continuing theme was that almost everyone in the renewable energy space benefits from tax credits and that energy storage technologies were maturing at such a rate that any targeted tax benefits would only be necessary for a few years. Moreover, one expert noted that application of the ITC to energy storage should be commonplace as Section 48 of the Internal Revenue Code (“IRC”) allows renewable energy paired with energy storage to receive the ITC – raising the question of why should energy storage not be able to receive credit as a stand alone, when it is performing the same function when paired with renewables. The expert suggested that the definition of which technologies qualify for the ITC be broadened to include energy storage. It should be noted that legislation has been introduced in both the Senate (S. 1868) and the House (H.R. 4649), proposing to amend the IRC to allow investment tax credits for energy storage technologies and battery storage technology.

Federal vs. state initiatives was another hot button topic, and it was noted that a number of states, such as New York and Massachusetts, have begun to adopt their own energy storage policies and roadmap)s. Nonetheless, most believed that a federal energy storage roadmap was imperative in order to reiterate the federal government’s commitment to energy storage, and to serve the critical function of educating stakeholders on the benefits of energy storage.

There is little doubt that energy storage technologies will become integrated in the renewable energy sector by necessity, given the intermittent nature of wind and solar power. However, the House is still grappling with how the federal government can best accelerate the development of the energy storage market and incentivize competition.

Jerry Muysis a partner and Kevin Fink is a law clerk with Boston-based law firm Sullivan & Worcester LLP.

As discussed in our posting covering continuing challenges to rebuild Puerto Rico’s electrical grid, the Puerto Rico Electric Power Authority (“PREPA”) has inhibited the recovery and redevelopment of the Island’s energy system. On July 25, 2018, the U.S. Congress House Committee on Natural Resources held an oversight hearing to discuss the “Management Crisis at the Puerto Rico Electric Power Authority and Implications for Recovery.” A panel of five witnesses – Bruce Walker (U.S. Department of Energy, Assistant Secretary of the Office of Electricity), Eduardo Bhatia (Puerto Rico Senate Minority Leader) and three energy and infrastructure advisors and consultants[1] – were present to testify and answer legislators’ questions. Puerto Rico’s Governor Ricardo Rosselló also was invited, but chose not to attend.

The hearing largely served to identify problems the Commonwealth of Puerto Rico currently is facing in seeking to rebuild its electrical grid, and provide perspectives regarding potential management, financial, and technical solutions. An issue repeatedly addressed was PREPA’s mismanagement of the power system, and its appropriate role in future decision-making regarding the system. Senator Bhatia emphasized PREPA’s mismanagement over the past 70 years. While he did not suggest eliminating PREPA entirely, he stressed the need for demonopolization, depoliticization, and the creation of an open energy market in which consumers could obtain energy through the deployment of microgrids. Microgrids allow for renewable energy to be generated and distributed close to the consumer, and may prove a more feasible option compared to traditional fossil fuel energy distribution, which requires transmission lines to cover many miles. If Puerto Rico’s electric grid were rebuilt, it would require construction, maintenance, and repair of transmission lines across the mountainous terrain in the populous northern portion of the island – including the capital San Juan – across to the southern portion of the Island, where most of the power generation occurs. Support for microgrid implementation, as is discussed in our prior posting, was echoed by the panel’s other witnesses.

Although absent from the hearing, Governor Rosselló did submit written testimony. On June 20, 2018, the Governor signed legislation, House Bill 1481, that provides a path forward for private sector involvement in energy generation and distribution. Regarding generation, the intent of the legislation is to either fully privatize PREPA’s assets or develop public-private partnerships. The legislation also provides that the electrical assets belong to the Commonwealth, but a consortium of companies would oversee energy distribution. The new law grants a period of 180 days for a special commission composed of the members of the Puerto Rican Senate, House of Representatives, and the Executive Branch to design a public policy and regulatory framework that will be used as a guide to award contracts and govern private sector transactions.

In his written testimony, the Governor stated that private sector involvement in the Island’s electric grid will assure a “modern, reliable, resilient, sustainable, and affordable electric system…catalyz[ing] sustained and long-term economic growth and job creation.” Several witnesses also favored privatization, which they opined may partially resolve concerns about PREPA’s history of mismanagement. The Governor further stated that, while support from the federal government is welcome, “additional legislation vastly expanding the role of the federal government… is simply not warranted.” Senator Bhatia, DOE Secretary Walker, and various House committee members agreed with the Governor’s comments that federalization of PREPA is not – and should not be – a goal of the U.S. government.

Nonetheless, the witnesses and many representatives agreed that some type of additional oversight of PREPA is necessary due to its insolvency, low credit rating, political entanglements, and history of mismanagement. One witness, Thomas Emmons of Pegasus Capital Advisors – who oversees his company’s renewable energy infrastructure investments – stated that PREPA must eliminate its debt and improve its credit to encourage private sector investment to help repower the Island. Following the hearing, on July 31, 2018, PREPA took a much needed step to improve its crippling financial condition; it reached a preliminary agreement with bondholders to restructure $9 billion of its debt. Notably, when asked at the hearing whether debt elimination and improved credit were the solution to the utility’s problems, Mr. Emmons responded that these steps are only a star; depoliticization and oversight of PREPA also are necessary.

Politics has long infiltrated PREPA’s decision-making and contributed to its organizational dysfunction. As recently as July 2018, the then current CEO of PREPA resigned stating it was “very clear [that] politics related to [his] compensation made it impossible for [his] contract to be fulfilled.” The PREPA Board then named a replacement, offering a higher base salary. Governor Rosselló took exception to the deal, publicly tweeting that the PREPA Board members must reduce the offered salary or resign – further illuminating the infusion of politics into the utility’s operation. The Board members offered their resignation, and Governor Rosselló appointed a new CEO who previously had worked at PREPA and was viewed as contributing to the agency’s mismanagement.

While the recent legislation seeks to partially privatize the Island’s electrical system, changes to PREPA’s management regime were not addressed. Episodes such as described above raise concerns that the utility’s institutional problems will continue to inhibit effective management practices.

The Committee hearing provided an opportunity for knowledgeable witnesses, federal government officials, and legislators to discuss the factors inhibiting the restoration and redevelopment of Puerto Rico’s electrical grid. While the extent of any further federal government involvement remains to be seen, there was a general consensus that oversight of PREPA’s management – removed from political influence – is a necessary starting point. Also potentially helpful is the preliminary agreement reached by PREPA with its bondholders, and approved last week by the Island’s Oversight Board, to restructure $9 billion of debt. If finalized, the agreement would serve as an important first step for PREPA to overcome its insolvency. And, if adequate oversight and management best practices finally are implemented at PREPA, the private sector may find Puerto Rico’s energy sector a more attractive investment opportunity.

Jeffrey Karpis a partner and Kevin Fink is a law clerk with Boston-based law firm Sullivan & Worcester LLP.

Sullivan & Worcester counsel recently participated in the “Grid Scale Energy Storage Summit,” part of the expansive Hydrovision International conference held at the end of June in Charlotte, North Carolina. For the first time on an international scale, the Summit brought together both energy storage and hydropower experts from around the world for the purpose of debating, among other things, the future role of hydropower in the mix of energy storage options.

In addition to Sullivan & Worcester and other counsel, energy sector participants included representatives from the U.S. Department of Energy, renewable energy trade associations such as the Solar Energy Industries Association, and Regional Transmission Organizations (“RTOs”) and Independent System Operators (“ISOs”). The hydropower industry was represented by a variety of trade associations including the National Hydropower Association, International Hydropower Association, and the Low Impact Hydropower Institute.

The energy storage industry is growing exponentially in the United States. Total installed capacity exceeded 1,000 MWh in 2017 – a record amount – and energy storage is forecast to add an additional 1,000 MWh capacity in 2018. As a result, energy industry experts in both the private and public sectors are grappling with how best to manage energy storage’s role in the electrical grid as well as capitalizing on the maturing industry.

Discussions focused on the role of energy storage in addressing new challenges to the reliability of the electric grid posed by increasing reliance on wind and solar, the implications and adequacy of new policies and regulations that have created expanded opportunities for energy storage participation in interstate markets, and whether sufficient market demand exists to encourage the pairing of “pumped hydro” with other renewable technologies such as wind and solar. “Pumped hydro” facilities are currently the predominant form of energy storage, and typically operate through the storage of water in one or more reservoirs. During periods of peak electricity demand, water from an upper reservoir is released to a lower one and moves through turbines to generate power. In instances of low demand, low-cost electricity from the grid is used to pump water back up into the upper reservoir.

A common theme throughout the Summit was the expression of frustration by the hydropower industry that while “pumped hydro” has existed since the 1920’s and currently accounts for 97% of the nation’s installed energy storage capacity, current regulatory policies tend to encourage the development of newer, not yet matured energy storage technologies such as batteries, compressed air, and flywheels. A consensus emerged regarding the need for a level playing field so that all energy storage technologies, including “pumped hydro,” are utilized to their greatest potential. It was further agreed that stakeholders and the public need to be educated regarding the untapped potential of “pumped hydro” and that the public’s perception of “pumped hydro” is often associated with large, conventional hydropower (which involves larger impacts from both an environmental and financial perspective) rather than smaller, local projects which can present lesser environmental impacts and financial burdens.

In conclusion, although the deliberations largely focused on hydropower’s role in the emerging energy storage market, there were many key takeaways that apply to the energy storage industry beyond just hydropower. Of particular interest was the February 2018 FERC Order 841, which directed RTO/ISOs to establish “participation models” for energy storage. While viewing Order 841 as a favorable start in terms of establishing a regulatory framework for energy storage, most conferees expressed the desire that FERC take a more expansive approach in the Order and set more explicit requirements governing “participation” and “interconnection,” but also acknowledged that each ISO/RTO region has different needs and resources to address those needs.

Jerry Muysis a partner and Kevin Fink is a law clerk with Boston-based law firm Sullivan & Worcester LLP.

In the nine months since Hurricane Maria, substantial progress has occurred in bringing Puerto Rico’s power grid back online. Some consumers with access to solar microgrid systems regained power as soon as a few days after the storm, while others who relied on traditional energy sources had to wait for the power grid to be repaired. Solar microgrid systems are unique; they offer solar-powered electricity in parallel with the traditional energy grid but can also disconnect from the grid in times of crisis and provide solar-powered energy to a smaller subset of consumers.

Ninety-five percent of the island’s consumers have had their electricity restored. Those still without power are concentrated largely in rural, hard-to-reach areas. In reality, though, while those without power number around 13,000, Puerto Rico’s entire population still is reeling from the effects of Maria. The damage sustained to homes and businesses remains overwhelming and quick fix solutions such as throwing tarps over gaping holes in roofs have become the status quo. Fear of recurring blackouts and the difficulty of persevering through the recovery process has fundamentally impacted the lives of Puerto Ricans. Thousands have fled the island, and the NY Times reported that many who remain have altered their everyday habits, such as only buying a few days’ worth of groceries at a time to guard against spoilage in the event of another power outage.

A variety of players have assisted in Puerto Rico’s power restoration efforts: the federal government, corporates, states and the Puerto Rico Electric Power Authority (“PREPA”). Immediately after Maria, the U.S. Army Corps of Engineers (the “USACE”) and the Federal Emergency Management Agency (“FEMA”) spearheaded the restoration and repair efforts. The USACE provided personnel to coordinate and manage those activities and to perform engineering and disaster-related relief, which included the delivery of over 1,000 generators to the island. More than 700 of these generators, including three “mega-generators” large enough to power hospitals and critical facilities, remain on the island ahead of the hurricane season.

Also, the USACE, with monetary and logistical support from FEMA, contracted with companies such as Fluor Corporation to perform restoration projects. Fluor reports that it installed over 493 miles of conductor wire and repaired or replaced close to 7,800 power poles. Several other companies, including Tesla, Sonnen, and Blue Planet Energy, donated and installed solar microgrid systems near community centers, water pump stations, critical infrastructure centers, and hospitals, where power grid resilience is particularly crucial. Six weeks after Hurricane Maria, PREPA requested assistance from a number of mainland states, a process that often begins in anticipation of a natural disaster. Shortly thereafter, crews of engineers, workers, and supervisors, along with equipment and replacement materials, arrived from Arizona, California, Florida, Massachusetts, and New York, and worked alongside the USACE and PREPA.

Despite its poor procurement track record, PREPA’s primary involvement with restoration projects has been to coordinate private sector contracts. Symptomatic of the ill effects of PREPA’s poor management, one of the companies with whom it contracted, Cobra, a subsidiary of Mammoth Energy, caused over a quarter of the island to plunge back into darkness. Cobra had employed a subcontractor to conduct restoration projects on the southern coast of the island. In April, the subcontractor’s excavator hit a major distribution line, which altered the voltage causing eight major plants to fail and leaving 870,000 people without power for two additional days. Following this incident, Puerto Rico’s Governor Roselló implored PREPA to cancel its contract with Cobra, the cost of which already had been increased on three occasions and ballooned to almost five times the original amount.

The instability of the island’s power grid before the hurricane was further exacerbated by the emergency fixes and stop-gap repairs made in Maria’s wake. PREPA’s CEO Walter Higgins has stated that projects to adequately strengthen the grid will take years to complete and cost between $5 and $8 billion. And, any hope of long-term assistance from USACE or FEMA was dashed when both federal agencies announced, at the start of the 2018 hurricane season, their impending departure from the island, thus leaving PREPA in charge of the daunting grid modernization task.

Fortunately, the Department of Energy (“DOE”) has worked with PREPA and recently released a report entitled “Energy Resilience Solutions for the Puerto Rico Grid.” The report recommends reducing dependence on fossil fuels and increasing reliance on natural gas and renewable energy, along with updating the infrastructure with monopoles, which are single-tower steel transmission towers. Monopoles are much more resilient than traditional lattice towers and withstood Maria’s wrath effectively. The report also urged Puerto Rico to begin establishing renewable energy microgrids for enhanced resilience and reliability. DOE’s report states that “microgrid investment has the potential to be more cost effective than alternative system upgrades to harden the system for improved function and reliability.” Solar energy sourced microgrids also are said to be more resilient in many ways: solar panels are easy to replace, the energy is generated right where it is consumed and does not need to travel long distances to reach consumers, and panels come back online as quickly as the sun can rise after a storm without having to wait for grid repairs.

The DOE’s findings regarding microgrids are consistent with prior experience in Puerto Rico, albeit on a limited scale. Solar-powered microgrids were implemented before Maria, and fared well during the storm. The Casa Pueblo community and ecology center, located in a rural section of Puerto Rico, installed microgrid solar panels over twenty years ago. Although FEMA was unable to reach Casa Pueblo’s mountain city of Adjuntas for weeks after the storm, Casa Pueblo regained power immediately after Maria passed. The community thus had electricity, and could provide food, water, tarps and medical treatment. As the DOE report notes, microgrids sourced by renewable energy can be deployed across the island and have the potential to curtail blackouts and prevent the months-long disruption to the electric system as occurred after Hurricane Maria. The DOE already has acted on its report recommendations, launching a pilot program to install half-a-dozen microgrids on the island in an effort to lessen weather-related risk and attract more outside investment.

Further, noting that the island’s grid is a “highly fragile and vulnerable system,” on June 20, 2018, Governor Rosselló removed from PREPA’s bailiwick the grid restoration by signing a bill to privatize the state-owned utility. The bill enables PREPA to sell its power generation plants and assets, seeks to facilitate public-private partnerships to modernize the power grid, and prevents a single entity from monopolizing the entire energy system. Many legislators view privatization as an opportunity to boost Puerto Rico’s economy while building a resilient and energy-efficient grid. Others prefer that PREPA be overhauled and remain in government hands, fearing that privatization will lead to higher prices for a dwindling customer base. Puerto Rico’s Power Union also has expressed skepticism that the grid’s low consumption rate coupled with its substantial infrastructure needs will dissuade private sector investors from entering into public-private partnerships as the bill envisions. Even some analysts who favor privatizing Puerto Rico’s power system have expressed concern that the bill enables the government to retain excessive controls over the envisioned private electric utilities.

A further concern is that the legislation fails to address PREPA’s and the Commonwealth’s bankruptcy status. The risks posed by the enormous debt make potential private sector investors nervous about repayment, although some of the obligations likely will be satisfied by PREPA’s sale of its assets and power plants. Also, both the DOE and Puerto Rico’s Financial Oversight and Management Board have projected that over $60 billion in federal funding will be provided to the island during the next decade, some of which likely will be earmarked for updating the energy grid.

On the heels of privatization, the Puerto Rico Energy Commission (“PREC”), the independent body created by Puerto Rico’s legislature to oversee the island’s energy policies and reforms, has promulgated regulations for microgrid development. Under these regulations, PREC will oversee a bidding process and select applicants to develop microgrid systems. While it is too soon to prognosticate the manner in which the private sector will respond to these regulations, corporates already have expressed interest in providing the technologies for the next phase of the rebuilding process. AES Corporation, which operates both a coal plant and solar plant on the island, repeatedly has suggested that a regionally-based microgrid system be implemented. Tesla also remains committed to the island’s energy development, and has discussed installing a back-up, high-capacity battery storage system for solar energy sourced microgrids that would provide alternative power in the event of another blackout.

Presently, patience is the name of the game. It is unknown whether recent legislative and regulatory developments will facilitate the necessary level of private sector involvement to successfully rebuild and strengthen Puerto Rico’s power system.

As previously discussed, offshore wind is well-developed outside the United States. In Europe, the first offshore wind facility was installed in 1991, and a record 3,148 MW of capacity was added in 2017. In comparison, the first and only operating offshore wind farm in the U.S. is Block Island, a 30 MW facility off the coast of Rhode Island, which began operation in 2016. While the U.S. lags behind European wind energy leaders, Northeast states have sought to facilitate large scale offshore wind development by setting goals and awarding contracts to offshore lease areas. These recent activities have been met with optimism and promise; however, there still are challenges beyond initially securing leases that must be met before offshore wind projects in the U.S. are successfully implemented from start to finish.

Within the past year, New York, New Jersey, Massachusetts, and Rhode Island have announced intentions to incorporate offshore wind resources into their respective energy portfolios. In January 2018, the New York State Energy Research and Development Authority (NYSERDA), issued an Offshore Wind Master Plan, which identified four areas for proposed offshore wind projects, each capable of supporting at least 800 MW. Acting on NYSERDA’s request, the Bureau of Ocean Energy Management (BOEM), the federal agency responsible for approving offshore lease areas beyond state jurisdiction (3 nautical miles offshore), sought public comment on the proposed areas (BOEM published a “Requests for Nominations: Commercial Leasing for Wind Power on Outer Continental Shelf in New York Bight” in the Federal Register, which gave the public until May 29, 2018 to respond). In May 2018, BOEM extended the comment period to July 30 at the request of New Jersey Governor Phil Murphy to enable the state to adequately address commercial fishing industry concerns. Also in May, Governor Murphy signed legislation committing New Jersey to develop 3,500 MW of offshore wind.

While the offshore wind industry in the U.S. is gaining momentum through lease awards, there still are several barriers that must be addressed if the industry is to successfully construct and operate wind farms. One such potential barrier is the federal Merchant Marine Act of 1920, more commonly known as the Jones Act. Originally enacted to ensure that a domestic merchant fleet could meet shipping needs in case of an international shipping conflict, the Jones Act, among other things, requires shipments made between U.S. ports to be conducted on U.S. vessels manned by U.S. citizens or permanent residents. Additionally, in the context of wind turbines, once a monopile -- the vertical piece struck into the seabed to secure the turbine -- is set into the seabed, it becomes a “point” under the Jones Act, triggering the “U.S. built and manned vessel” requirement. An exception to this requirement is that merchandise may be transferred by foreign crane in conjunction with U.S. vessels transporting materials between points. This method was used to install the 30 MW Block Island Wind Farm; however, industry experts have commented that while the approach worked for a small scale wind farm, it may be too costly for larger scale projects. Therefore, a major consideration may arise shortly because no U.S. entity presently owns Jones Act-compliant vessels capable of transporting and installing large scale offshore wind turbines.

However, some stakeholders have questioned whether the Jones Act applies to offshore wind projects. The Jones Act’s jurisdiction reaches three nautical miles from shore, and the proposed offshore wind projects in the Northeast are beyond that range. Thus, clarification is required as to whether activity occurring outside three nautical miles from shore is subject to the Jones Act. The applicability of another federal law, the Outer Continental Shelf Lands Act (OCSLA), to offshore wind installations also needs to be clarified. The OCSLA initially was enacted to address the exploration, development, and production of mineral resources, but in 2005 Congress amended the law to include licensing requirements for “alternative energy” projects. There still is ambiguity regarding whether the OCSLA applies to offshore wind installations. If both the Jones Act and OCSLA are determined to apply to offshore wind projects, development may be stymied from both a transportation standpoint (via point to point shipments), and in the licensing and construction of projects.

Various approaches to address these potential constraints have been proposed to eliminate any further delay once the leasing stage of a wind farm is completed. A long-term solution, to build Jones Act compliant vessels, already has begun with the first vessel expected to be delivered by the end of 2018. However, some short-term measures also could be taken to further facilitate offshore wind development. Regarding the ambiguity surrounding the jurisdictional reach of the Jones Act, a waiver could be pursued for renewable energy projects until the supply chain side of the industry is mature enough to handle all of the transportation and construction phases domestically. Additionally, an advisory ruling could be sought from U.S. Customs and Border Protection (CBP) regarding whether the OCSLA applies to offshore wind projects.

A second challenge facing offshore wind developers is that U.S. ports will require infrastructure upgrades to handle wind turbine parts that are more than 800 feet tall with blades the length of a football field. Currently, there are no ports or manufacturing facilities in the Northeast capable of adequately handling these parts. In January 2018, the Coalition for More Efficient Ports -- whose members include the Port Authority of New York and New Jersey -- sent a letter to President Trump highlighting the need for ports to receive adequate federal funding. Moreover, Orsted A/S, a Denmark power company with offshore wind projects worldwide, publicly called for East Coast states to expand their ports to accommodate offshore wind development.

Thirdly, delays have ensued due to stakeholder litigation over potentially negative impacts from turbine construction and operation. For example, Statoil (now Equinor), which was awarded a lease for an offshore wind facility off the coast of New York in December 2016, has faced considerable delays from a lawsuit filed against BOEM by the Fisheries Survival Fund and other commercial fishing organizations, businesses, and three municipalities alleging violations of several federal environmental laws, including the National Environmental Policy Act (NEPA). The case, Fisheries Survival Fund v. Jewell, No. 16-cv-2409, is ongoing in U.S. District Court for the District of Columbia. Thus, developers must be cognizant of opposition from interest groups, and be prepared to address their concerns.

Therefore, while states in the Northeast are ramping up plans for large scale offshore wind farms, it is important that developers fashion strategies to address impediments, including the potential impact of Jones Act and OCSLA requirements, port expansion needs, and stakeholders’ environmental and other concerns.

Jeffrey Karpis a partner and Kevin Fink is a law clerk with Boston-based law firm Sullivan & Worcester LLP.

The United States has produced clean, renewable electricity from hydropower for more than 100 years. Today there are approximately 2,500 domestic dams and pumped-storage facilities that provide roughly 100 gigawatts (“GW”) of electricity. In addition, there are more than 80,000 non-powered dams, i.e., existing structures that could produce power, with the potential capacity of 12 GW. New England’s non-powered dams potential capacity is 243 mega watts (“MW”). Many of the 80,000 non-powered dams could be converted to produce hydropower at relatively low cost and within a relatively short timeframe. See U.S. Department of Energy, An Assessment of Energy Potential at Non-Powered Dams in the United States (2012).

The energy storage rule, Order No. 841, issued on February 15, 2018 by the Federal Energy Regulatory Commission (“FERC”), creates new opportunities for hydropower facilities to participate in the wholesale power market, and thus incentivizes the conversion of non-powered dams to hydropower and the addition of storage to existing hydropower facilities. This article explores the opportunities presented by the new energy storage rule, particularly with respect to small, low-head non-powered dams where the installation of energy generation capacity can be achieved with lower installed costs, lower levelized cost of energy, fewer barriers to development, less technological and business risk, and in a shorter time frame than development requiring new dam construction. Moreover, energy from low-head hydropower installations can be aggregated for coordinated dispatch into a regional transmission organization (“RTO”), thereby leveraging its ability to be a peak shaving resource, which is an area FERC has determined is important for removing barriers, but has concluded should be the subject of a separate proceeding in order to permit the Commission to gather more information.

UNDERSTANDING ENERGY STORAGE

An “energy storage resource” is a commercially available technology that is capable of absorbing energy, storing it for a period of time, and thereafter dispatching the stored energy to the wholesale or retail electricity market. Existing technologies include (1) batteries (lead acid, lithium ion, sodium sulfur, flow, dry cell); (2) fly wheels (mechanical devices that harness rotational energy to deliver instantaneous electricity); (3) compressed air storage that uses electricity to compress air and store it, which is then expanded through a turbine to generate electricity later; (4) electrochemical capacitors that store electricity in an electrostatic charge; (5) thermal energy storage that uses either heat sinks like molten salts to store heat energy which can be used to either generate electricity or provide heating later; or electricity to freeze water into ice that can be used to provide air conditioning later and (6) pumped hydro power. New developing battery technologies include, for example, sodium-ion and solid magnesium electrolyte.

Energy storage technologies are viewed favorably by most regulatory bodies for many reasons that conform to smart energy policy. They can reduce the emission of greenhouse gases, reduce demand for peak electrical generation, defer or substitute for an investment in generation, transmission or distribution assets, improve the reliable and stable operation of the electrical transmission or distribution grid and reduce or eliminate variability and flicker that accompany some renewable energy sources. These storage technologies are seen as essential to the continued expansion and value of renewable energy, and as key to balancing energy generation and consumption and to maintaining grid stability.

Prior to issuance of the current rule, FERC regulated U.S. interstate wholesale electrical energy markets by participant categories – generators, transmitters and distributors, with different rules for different categories. While generators were authorized to sell into the wholesale market at market-based rates, transmission remained largely subject to cost-of-service ratemaking and required strict adherence to open-access transmission tariffs and non-discriminatory service to customers.

Because energy storage technologies can both inject electricity into as well as withdraw (i.e., be charged by) electricity from the grid, they transcend the Commission’s traditional “siloed” regulatory framework for generation, transmission and distribution resources. Understandably, therefore, FERC’s rules on how to connect energy storage to the electricity grid were inadequately defined and were designed to accommodate traditional technologies that are markedly different from energy storage. See Massachusetts Clean Energy Council and Massachusetts Department of Energy Resources, State of Charge: Massachusetts Energy Storage Initiative (2016).

FERC’S ENERGY STORAGE RULE

In November 2016, FERC proposed amendments to its regulations to remove barriers that discouraged energy storage resources and distributed energy resources aggregators from participating in the capacity, energy and ancillary services markets operated by the six regional transmission organizations (“RTOs”) and independent system operators (“ISOs”) subject to FERC jurisdiction. Pending public comment on the proposed rule, in January 2017 FERC issued a policy statement clarifying that an energy storage resource may provide services at both cost-based (e.g., transmission, which is regulated) and market-based (generation, which may be non-regulated or market-based) rates at the same time so long as (1) there is no double recovery of costs to the detriment of cost-based ratepayers, (2) the potential for cost recovery through cost-based rates does not inappropriately suppress competitive prices in wholesale electric markets to the detriment of other competitors who do not receive such cost-based rate recovery, and (3) the level of control in the operations of the electric storage resource by an RTO/ISO does not jeopardize its independence from market participants.

The February 2018 final rule adopted the conceptual approach set forth in the 2016 proposed rule and 2017 policy statement. That approach opened and leveled the playing field for energy storage resources by making the resources eligible to participate in the wholesale capacity, energy, and ancillary services markets. FERC deferred regulatory action with respect to distributed energy resources aggregators until a later date. The final rule provides regulatory flexibility to effectively deploy energy storage technologies in an array of applications that include improving (i) utility energy efficiency as well as grid stability and security; (ii) grid modernization; (iii) emergency back-up power; (iv) effectuating full use of variable renewable clean energy production facilities such as solar and wind; and (v) lowering annual energy costs. Each of these applications will contribute to expand state renewable portfolio standards goals and replace fossil fuel and nuclear generating plants.

APPLICATION TO HYDROPOWER

Energy storage resources that are deployed in conjunction with, and charged by small, low-head hydropower projects, can function as an independent energy source that provides: (1) reliable energy for a predictable time period, (2) peak power shaving at a substantially lower cost of electricity than the cost of peak power from conventional fossil-fueled sources, (3) reduced variability and flicker that have accompanied renewable energy sources, and (4) reduced greenhouse gas emissions by displacing demand for more natural gas powered electric power generating plants and natural gas pipelines that have heretofore been relied on to satisfy peak demand. In addition, the Senate Energy and Natural Resources Committee will shortly take up consideration of H.R. 2786, an amendment to the Federal Power Act to incent small-conduit hydropower. The bill passed the House last year 420-2.

Pursuant to Section 203 of the Federal Power Act (“FPA”), a hydropower facility must be licensed by FERC, receive an order from FERC indicating that it is non-jurisdictional to FERC, or obtain a determination from FERC that it is a “qualifying conduit hydropower facility.” FERC requires federal licensing when a hydropower project ties into the grid because interstate commerce is affected.

A non-federal hydroelectric project must also be licensed if it is located on a navigable water of the United States. The complicated issue regarding which waters are deemed “navigable” for purposes of federal jurisdiction is currently being litigated, and the current EPA is seeking to rescind and revise the navigability rules promulgated during the Obama Administration. Non-federal hydroelectric projects are also subject to federal jurisdiction if they (1) occupy lands owned by the United States; (2) use surplus water or water power from a government dam; or (3) are located on a body of water over which Congress has Commerce Clause jurisdiction, project construction occurred on or after August 25, 1935, and the project affects the interests of interstate or foreign commerce. See GZA GeoEnvironmental, Inc., Report on Permitting Small and Low Impact Hydropower Projects in Massachusetts (2016).

Even small hydroelectric projects that are connected to the interstate grid are deemed to affect interstate commerce by displacing power from the grid, and if the cumulative effect of the national class of these small projects is deemed significant for purposes of FPA section 23(b)(1). However, FERC does not require federal licensing if the hydro project is not tied into the grid, but its power is simply used on site.

Battery storage currently is a preferred technology for shaving peak energy demand and eliminating variability and flicker in renewable, clean energy resources, whether solar, wind or low-head hydropower. Especially important is the fact that battery storage generally can be deployed more quickly and flexibly than other storage technologies to meet peak demand, and at a cost that is expected to continue its significant rate of decline. Hydropower also runs twenty four hours a day seven days a week, subject to water level and environmental requirements. Further, according to the Low Impact Hydropower Institute (“LIHI”), the average capacity factor for LIHI Certified Hydropower is 54.4%. A “capacity factor” describes how intensively a fleet of generators is run. A capacity factor near 100% means operation is continuous close to 100% of the time. In comparison to low-head hydro, the 2017 capacity factor for nuclear was 92.2%, natural gas fired combined cycle – 54.8%, coal - 53.5%, wind - 36.7%, and solar photovoltaic – 27.0%.

CONCLUSION

A significant opportunity is presented by the potential development of hydro-charged battery storage for peaking facilities at currently existing small to midsize hydro sites. Peaking facilities can be deployed quickly, although installation may require upgraded and smarter transmission and grid infrastructure as well as new grid interconnection construction. Smart siting and distributed grid integration of battery stored power through hydroelectric generation can significantly reduce the pressure to build more natural gas pipelines to meet peak demand, and cut costs if available when natural gas prices for electricity generators peak. Other benefits would include enhanced grid reliability, and relatively more stable and predictable electricity prices since these hydroelectric peaking facilities would have small marginal operating costs.

Advanced energy storage resources are capable of dispatching electricity within seconds without producing direct air emissions. Therefore, significant modifications would not have to meet air quality standards.

In addition, the permitting process for advanced energy storage projects is simpler than for more complex infrastructure projects, and construction timelines are considerably reduced. The modular design of many energy storage systems allow components to operate and interconnect the storage resource using simple containerized structures. Such projects require a much smaller footprint than conventional power plants and easily can be added in local areas to provide grid stability, thus eliminating the need for new gas-fired generation or new transmission facilities to solve local reliability needs.

In September 2017, Hurricane Maria swept through the Commonwealth of Puerto Rico decimating the island, taking hundreds of lives and demolishing infrastructure on an enormous scale. In the hurricane’s immediate aftermath, Puerto Rico lost 100% of its power usage.

The energy infrastructure, which is 98% fossil fuel dependent, was severely damaged to the point that some observers considered repair impractical. In the first few months after the hurricane, power only had been restored to 70% of the Island’s residents.

In addition to the destruction Hurricane Maria imposed on Puerto Rico’s energy infrastructure, the Puerto Rico Electric Power Authority (“PREPA”), the main governmental authority with jurisdiction over energy and infrastructure, exacerbated the problems. With $9 billion of debt, in July 2017, PREPA filed for bankruptcy relief due to the cumulative impact of years of mismanagement, mounting operation and maintenance problems, the failure to recover the costs of providing power to its customers, years’ long battles with creditors, and a diminished workforce. Further, PREPA was unprepared for a major storm of Maria’s magnitude. As Governor Ricardo Rosselló publicly acknowledged, none of the storm response plans could account for years of poor maintenance of a broken-down electric grid.

Following the hurricane, PREPA sought outside assistance to repair and improve the Island’s energy infrastructure; however, this effort was unsuccessful. On October 17, 2017, PREPA entered into a $300 million contract with Whitefish Energy to rebuild its power grid. Due to Whitefish’s small size, lack of credentials and some questionable contract terms, investigations were initiated by the House Committee on Natural Resources and the FBI, and, Governor Rosselló canceled the Whitefish contract on October 29.

In light of PREPA’s inability to restore power to its customers, in November 2017, the United States Army Corps of Engineers (“USACE”) assumed primary control of the energy recovery efforts. Armed with emergency funding allotments from the U.S. Congress, USACE entered into an $860 million contract with the Louis Berger Group to supply temporary power to residents through the end of September 2018, and an $831 million contract with Fluor Energy to help restore electricity to the Island’s residents via improved energy infrastructure.

More recently, in late January 2018, Governor Rosselló announced plans to privatize PREPA. Under the Governor’s proposal, although the Commonwealth would retain ownership of PREPA’s transmission and distribution systems, a private operator would be selected to operate the systems for a period of years. The privatization plan has been met with skepticism, in part based on the past failed attempt to privatize another Puerto Rico utility, the Aqueduct and Sewer Authority. Also, concerns were expressed that the savings promised by private operators may not materialize due to future economic development decisions being left in the hands of those primarily concerned with the return on investment to shareholders.

Regardless of whether the Island’s electric utility is privatized, energy infrastructure experts have suggested that the focus shift to developing distributed renewable energy resources to be delivered both on an upgraded power grid and a series of microgrids. A microgrid is a segment of a larger electric grid that can detach and operate on its own to provide localized electricity during, for example, a larger grid shutdown or failure. When operating in tandem with the main grid, a microgrid’s ability to produce energy locally enables customers to draw far less power from the main grid, thereby reducing strain on the main grid. Microgrids also can operate independently, thus offering protection during peak usage hours, primary power outages, or if the main grid becomes unstable.

Additionally, wind, solar, biomass, geothermal and small hydro are more practical for use in microgrids because such renewable energy resources typically are decentralized, meaning that generation and transmission occur within a smaller service area. This decentralization lowers costs and reduces carbon emissions. In contrast, conventional power stations that operate on fossil fuel have higher carbon emissions and are centralized, requiring electricity transmission over longer distances at a higher cost.

Puerto Rico has endured large-scale destruction, especially to its energy infrastructure. Critical regulatory and policy decisions must be made in the coming months. These decisions will impact the manner in which Puerto Rico redevelops its energy infrastructure and the energy resources that are deployed by the Commonwealth. Regardless of the outcome of the privatization efforts, the development of renewable energy sources and the use of microgrids appear to be a step in the right direction for Puerto Rico’s infrastructure renovation.

Despite the new administration’s efforts to rollback Obama Era environmental regulations, most businesses in the U.S. are maintaining their commitments to sustainability. According to Lucid’s 2017 Sustainability Outlook Report, only 5% of private companies surveyed expect to decrease their commitment to sustainability programs in 2017, while 74% expect no change and 21% expect an increase in their commitments. Growing concern about climate change have presented companies with the opportunity to lead the way by increasing their sustainability efforts. Major companies are taking the threat of climate change more seriously, and already are developing solutions to reduce their greenhouse gas (GHG) emissions.

Opportunities abound for U.S. businesses to get involved in corporate sustainability. For those businesses that are up to the challenge, the MIT Sloan Management Review’s 2017 Research Report offers eight evidence-based factors to consider. First, articulate a practical sustainability vision and ambition that lays the foundation for new business practices. Second, identify and prioritize material issues to focus resources. For example, following its Environmental Sustainability Plan’s goal "to provide clean, fuel-efficient and dependable power for our customers with the least environmental impact possible,” Cummins Inc. recently decided to expand a wind farm in northern Indiana by adding an additional 75 megawatts of capability.

Third, embed sustainability organizationally through cross-functional teams, clear targets, and key performance indicators. As noted in the Journal of Accountancy, it is important that the chief financial officer (CFO) be part of and buy into the sustainability initiatives in order to facilitate an integrated company perspective. Fourth, innovate on multiple dimensions of your business model. Nestlé, for example, recently began placing “How2Recycle” labels on its half-liter bottles manufactured in North America. This activity is in line with the company’s sustainability target to “find a compelling and simple way to educate and encourage all Americans to recycle the bottle.” Not only does Nestlé’s How2Recycle project encourage recycling plastic bottles, but it also instructs consumers to empty and replace caps on bottles, resulting in fewer caps ending up in our waterways and oceans.

Fifth, develop a clear business case, and sixth, get the board of directors on board. Sustainability, while beneficial to the environment, also can be a business driver. As pointed out by the Journal of Accountancy, sustainability-related risks – extreme weather events, water crises, and climate change – are business risks. Furthermore, corporate sustainability have been proven to result in economic efficiency. For example, Unilever found that its “Sustainable Living” brands have grown 50% faster than the rest of its business because of consumer demand for sustainable products.

Seventh, communicate a sustainability value-creation story to your shareholders. Eighth, collaborate with a variety of stakeholders to drive strategic change. For example, 62 percent of Exxon Mobil Corporation’s shareholders recently voted for a resolution that requires the company to annually disclose how it will be affected by global efforts to mitigate the effects of climate change. Similarly, Occidental Petroleum Corp.’s shareholders recently approved a proposal requiring the company to report on climate change impacts to business.

Although President Trump has denied the impact of human activity on climate change and is actively seeking to resurrect the fossil fuel sector, nonetheless, it appears that U.S. businesses are maintaining their commitments to sustainability.

Leigh Ratino is a law clerk with Boston-based law firm Sullivan & Worcester LLP.

President Trump is spearheading a government-wide roll back of Obama Era climate initiatives. The president and his EPA Administrator, Scott Pruitt, have delivered a one-two punch. They both have denied the impact of human activity on climate change, while seeking to resurrect the moribund fossil fuel sector. In March 2017, the President issued a wide-ranging “Energy Independence” Executive Order requiring review and reconsideration of any rule that might burden development of domestic energy sources, particularly oil, gas, coal and nuclear energy. After much drama, in June 2017, President Trump fulfilled a campaign promise to withdraw the United States from the Paris Climate Accord (“Accord”). Moreover, in seeking to implement the new Administration’s energy independence strategy, government departments and agencies are pursuing delay or repeal of regulations aimed at curbing greenhouse gas (“GHG’) emissions, most notably EPA’s targeting for elimination the Clean Power Plan rule (“CPP”).

Under the Accord, the United States had pledged to reduce its greenhouse gas emissions 26-28% below 2005 levels by 2025, and to contribute up to $3 billion in aid to an international fund that helps the world’s poorest nations mitigate the effects of climate change. It was expected that one of the President’s first acts following the inauguration would be to withdraw the country from the Accord. On the campaign trail, Mr. Trump had not minced words about his view of the Accord, and his belief that climate change was a hoax. Nonetheless, the President delayed his decision, while considering the views of many who advocated that the United States remain in the Accord, including several of his advisors, former Vice President Gore, the leaders of the G-7 nations, state governors and corporate executives. President Trump, however, announced on June 2, 2017 the country’s withdrawal from the Accord, declaring the overarching need to protect United States workers and businesses from intrusive environmental restrictions, and negative impacts on economic growth. In response to the President’s decision, a coalition of states, companies, and institutions have pledged to fulfill the United State’s emissions reduction commitment.

The withdrawal from the Accord appears unlikely to affect ongoing domestic efforts to reduce GHG emissions. Currently, 29 states and the District of Columbia have enacted renewable portfolio standards (RPS) to increase the amount of electricity generated from renewable energy sources. Since the beginning of 2016, seven states have even increased their commitments for additional wind and solar-generated power.

Between 2005 and 2015, GHG emissions decreased by roughly 20% in the electricity sector, 10% in the transportation sector, 4% in the industry sector, and 0.7% in the agriculture sector.

In addition to negating the impact of global warming, the Trump administration seeks to resuscitate the fossil fuel sector by removing regulatory impediments to growth. As noted, on March 28, 2017, President Trump issued an EO that instructed EPA to reconsider the CPP and “as soon as practicable, suspend, revise or rescind” the rule. Promulgated in 2015 under the Clean Air Act, the CPP is expected to facilitate a reduction in carbon dioxide emissions from the utility power sector by 32 percent below 2005 levels by 2030. However, the rule has been tied up in litigation. Shortly after promulgation, the Supreme Court stayed the CPP’s implementation. A ruling on the CPP’s validity is awaited from the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) following an en banc hearing in September 2016. In the meantime, on April 4, 2017, EPA issued a notice of intent to review the CPP, while seeking to delay the D.C. Circuit’s impending decision on the rule’s validity. On April 28, 2017, the court denied the EPA’s request to indefinitely delay the litigation while the Agency reconsiders the need for the CPP. Instead, the D.C. Circuit agreed to hold the litigation in abeyance for 60 days, and ordered the parties to submit briefs addressing whether the court should continue to delay its decision or dismiss the litigation and remand the rule to the EPA. After reviewing the parties’ briefs, on August 8, 2017, the court ordered that the cases remain in abeyance for an additional 60 days, and that EPA submit status reports in 30-day intervals.

More recently, EPA attempted unsuccessfully to secure a lengthy delay in implementing another Obama Era emissions reduction regulation. That rule requires that oil and gas companies fix methane leaks and upgrade equipment at extraction sites. Siding with the NGOs, who challenged EPA’s announced two year delay, the D.C. Circuit ruled that EPA lacked authority under the Clean Air Act to stay the regulation while the Agency reconsiders it. On August 10, 2017, the D.C. Circuit rejected industry groups and states’ request to reconsider the ruling.

Moreover, the President’s Energy Independence EO lifts the moratorium on leasing federal land for coal mining, and instructs the Department of Interior (“DOI”) to consider rescinding the 2015 regulation of hydraulic fracturing on federal and tribal lands. In June 2016, a Wyoming federal judge struck down the rule, which subsequently was appealed to the Tenth Circuit. DOI’s Bureau of Land Management (“BLM”) has requested the Tenth Circuit to stay the litigation while it reviews the need for the regulation. On July 25, 2017, BLM published a proposal in the Federal Register to rescind the 2015 regulation, asserting that it needlessly burdens industry with unjustified compliance costs. The Tenth Circuit has yet to rule on BLM’s stay request.

To further assist the domestic energy sector, President Trump’s Energy Independence EO also seeks to ease permitting of fossil fuel energy projects. In particular, the EO rescinds an Obama Era directive that federal agencies performing National Environmental Policy Act (“NEPA”) project reviews must consider GHG and climate change impacts. Shortly after taking office, President Trump approved the permits for the TransCanada Corp’s Keystone XL pipeline and the Dakota Access pipeline. In response, the Standing Rock Sioux Tribe and other Native American tribes challenged issuance of the final permit to complete construction of the Dakota Access pipeline in the U.S. District Court for the District of Columbia. On June 14, 2017, the court ruled that aspects of the Army Corps of Engineers’ (Corps) environmental assessment were inadequate, and ordered the Corps to conduct further review. But, the court refused to grant the plaintiffs’ requested injunctive relief to halt oil pumping operations pending the Corps performance of further environmental review, which is expected to be completed by the end of the year.

Despite President Trump’s efforts to provide a “leg up” to the fossil fuel sector, it seems doubtful that the decline in coal-fired power generation will be reversed for several reasons. First, coal is not competitive with lower-priced and widely-available natural gas. Second, the cost of developing renewable energy resources continues to drop. Third, state RPS programs and corporate commitments to reduce greenhouse gas emissions continue to drive the growth of the renewables market. Fourth, carbon emissions from power plants have fallen by 5% during each of the last two years, which is largely due to the switch by the utility sector, coal’s largest customer, to natural gas and renewables. Currently, coal’s market share is in the low 30% range, and is unlikely to increase despite the new administration’s efforts to revitalize the industry.

Furthermore, withdrawal from the Paris Climate Accord is unlikely to have short-term impacts in the United States. Carbon dioxide emissions from United States’ energy sources are expected to hit a 25-year low in 2017, and to continue to decrease. Thus, it appears that the train already has left the station regarding the overriding support by many corporations and states for the increased development of renewable energy resources, and the ongoing conservation and sustainability measures to further reduce greenhouse gas emissions. In light of the foregoing developments, it seems that market forces, not President Trump’s EO or government agencies’ efforts, will dictate the fate of the fossil fuel industry.

Jeffrey Karp is a partner and Leigh Ratino is a law clerk with Boston-based law firm Sullivan & Worcester LLP.